Pumping systems, such as electric submersible pumping systems, are commonly used to transport fluids from a first location to a second remote location. An example of such a system is that used for transporting subterranean reservoir fluids from one location to another. A conventional application involves the pumping of fluids from a wellbore to a collection location at the surface of the earth.
Difficulties in transport can arise when the fluid to be transported is too viscous for adequate flow, and/or the fluid has an excessive gas-to-liquid ratio. Both of these types of problems can result in inadequate flow of the fluids through the pumping system and eventual system failure. The present invention solves such problems associated with pumping certain subterranean fluids.
Attempts have been made to lower the viscosity of high viscosity fluids by deploying heaters, in the form of heat trace tape and coil elements, in the wellbore. Such prior heater solutions, however, can have limited applications, require expensive secondary power cabling, and are prone to damage due to thermal cycling and corrosive environments. Oversized pumps and motors also have been used to pump such fluids. This solution, however, is less cost efficient, as the larger pumps and motors are substantially more expensive, require higher cost power cable and incur greater electric utility costs.
Other attempts have been made to inject well fluid with lower viscosity fluids or steam from a secondary and independent supply. The injection approach, while functional, requires an expensive supply source and tubing for directing the injected fluids. Such injection systems require regular maintenance and make the installation and support complex and expensive. Also, steam injection causes an increase in the gas-to-liquid ratio, thereby reducing the overall pumping system efficiency and potentially causing gas lock in the pump.
With respect to high gas-to-liquid ratio well fluids, problems include failure of the pumping system or at least a significant decrease in the overall efficiency of the pumping system. Prior solutions have included installation of commercially available rotary gas separators. While such gas separators are generally effective, they add cost to the system and have limited efficiency.
Other attempts have been made to locate the pumping equipment below the wellbore fluid inlet for the reservoir, e.g. wellbore casing perforations. While locating the equipment below the reservoir inlet has been effective for allowing a portion of the free gas to naturally vent to a location above the reservoir, a problem with this approach is that it can result in an inadequate flow rate past the motor, thereby causing excessive motor heating and resultant failures. Although excessive motor heating has been addressed in these applications through secondary solutions, such as flow diverting shrouds and recirculation systems, such secondary solutions are designed to cool the motor and are not intended to lower the gas-to-liquid ratio.
There is an increased need to provide enhanced and hybrid solutions to the problems of high viscosity and high gas-to-liquid ratios in wellbore fluids to facilitate production from otherwise marginal reservoirs.